Oil sand extraction processes are used to liberate and separate bitumen from oil sands so that the bitumen can be further processed to produce synthetic crude oil. Numerous oil sand extraction processes have been developed and commercialized, many of which involve the use of water as a processing medium. Other processes are non-aqueous solvent-based processes. Solvent may be used in both aqueous and non-aqueous processes.
One water-based extraction process is the Clark hot water extraction process (the “Clark Process”). This process typically requires that mined oil sands be conditioned for extraction by being crushed to a desired lump size and then combined with hot (for instance about 95° C.) water and perhaps other agents to form a conditioned slurry of water and crushed oil sands. In the Clark Process, an amount of sodium hydroxide (caustic) may be added to the slurry to adjust the slurry pH upwards, which enhances the liberation and separation of bitumen from the oil sands. Other water-based extraction processes may use other temperatures and may include other conditioning agents, which are added to the oil sand slurry, or may operate without conditioning agents.
Regardless of the type of water-based extraction process employed, the process will typically result in the production of a bitumen froth that requires treatment with a solvent. For example, in the Clark Process, a bitumen froth stream comprises bitumen, fine particulate solids (also referred to as mineral or inorganic solids) and water. Certain processes use naphtha to dilute bitumen froth before separating the product bitumen by centrifugation. These processes are called naphtha froth treatment (NFT) processes. Other processes use a paraffinic solvent, and are called paraffinic froth treatment (PFT) processes, to produce pipelineable bitumen with low levels of solids and water. In the PFT process, a paraffinic solvent (for example, a mixture of iso-pentane and n-pentane) is used to dilute the froth before separating the product, diluted bitumen, by gravity. A portion of the asphaltenes in the bitumen is also rejected by design in the PFT process and this rejection is used to achieve reduced solids and water levels. In both the NFT and the PFT processes, the diluted tailings—comprising water, solids and some hydrocarbon—are separated from the diluted product bitumen.
Solvent is typically recovered from the diluted product bitumen component before the bitumen is delivered to a refining facility for further processing.
One PFT process will now be described further, although variations of the process exist. The PFT process may comprise at least three units: Froth Separation Unit (FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU). Two FSUs may be used, as shown in FIG. 1.
With reference to FIG. 1, mixing of solvent with the feed bitumen froth (100) is carried out counter-currently in two stages: FSU-1 and FSU-2, labeled as Froth Separation Unit 1 (102) and Froth Separation Unit 2 (104). The bitumen froth comprises bitumen, water, and fine solids (also referred to as mineral solids). A typical composition of bitumen froth is about 60 wt % bitumen, 30 wt % water, and 10 wt % solids. The paraffinic solvent is used to dilute the froth before separating the product bitumen by gravity. Examples of paraffinic solvents are pentane or hexane, either used alone or mixed with isomers of pentanes or hexanes, respectively. An example of a paraffinic solvent is a mixture of iso-pentane and n-pentane. In FSU-1 (102), the froth (100) is mixed with the solvent-rich oil stream (101) from the second stage (FSU-2) (104). The temperature of FSU-1 (102) is maintained at, for instance, about 60° C. to about 80° C., or about 70° C., while the solvent to bitumen (SB) ratio may be from 1.4:1 to 2.2:1 by weight or may be controlled around 1.6:1 by weight for a 60:40 mixture of n-pentane: iso-pentane. The overhead from FSU-1 (102) is the diluted bitumen product (105) (also referred to as the hydrocarbon leg) and the bottom stream from FSU-1 (102) is the tailings (107) comprising water, solids (inorganics), asphaltenes, and some residual bitumen. The residual bitumen from this bottom stream is further extracted in FSU-2 (104) by contacting it with fresh solvent (109), for instance, in a 25 to 30:1 (w/w) SB ratio at, for instance, about 80° C. to about 100° C., or about 90° C. Examples of operating pressures of FSU-1 and FSU-2 are about 550 kPag and 600 kPag, respectively. The solvent-rich oil (overhead) (101) from FSU-2 (104) is mixed with the fresh froth feed (100) as mentioned above. The bottom stream from FSU-2 (104) is the tailings (111) comprising solids, water, asphaltenes and residual solvent, which is to be recovered in the Tailings Solvent Recovery Unit (TSRU) (106) prior to the disposal of the tailings (113) in tailings ponds. The recovered solvent (118) from TSRU (106) is directed to the solvent storage (110). Solvent from the diluted bitumen overhead stream (105) is recovered in the Solvent Recovery Unit (SRU) (108) and passed as solvent (117) to Solvent Storage (110). Bitumen (115) exiting the SRU (108) is also illustrated. The foregoing in only an example of a PFT process and the values are provided by way of example only. An example of a PFT process is described in Canadian Patent No. 2,587,166 to Sury.
To meet bitumen product quality, it is important for the diluted bitumen from FSU-1 to be below a set maximum amount of contaminants. Bitumen quality refers to the amount of selected contaminants in the process stream. Contaminants may include asphaltenes (comprising metal porphyrins) and inorganic solids (comprising inorganic elements, e.g. Si, Al, Ti, Fe, Na, K, Mg, and Ca). Achieving target bitumen quality is important as the contaminants may adversely affect the refinery processing of the product bitumen.
One known method of determining the solids content is to analyze samples in a laboratory using ASTM D4807. This method is not suitable for controlling bitumen quality while the froth is being processed.
Canadian Patent Application No. 2,644,821 (Chakrabarty et al.) filed on Nov. 26, 2008, published on May 26, 2010, in the name of Imperial Oil Resources Limited, describes the use of a native bitumen marker for controlling the SB ratio of a process stream during solvent-assisted bitumen extraction. That application describes using one or more native bitumen markers (for example, sulfur, nickel, vanadium, iron, copper, manganese, or chromium) to measure the SB in a process stream, for instance a stream from a froth separation unit (FSU) and/or to measure hydrocarbon loss, for instance in a tailings solvent recovery unit (TSRU).